1. Field of the Invention
Embodiments of the present invention generally relate to an adapter kit for use between a setting tool and a wellbore plug.
2. Description of the Related Art
When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, formation treatment, such as hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Typically, lateral holes (perforations) are shot through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing consists of injecting viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant material, such as sand, ceramic beads, or other materials, is generally injected-with the later portion of the fracturing fluid to hold the fracture(s) open after the pressures are released. Increased flow capacity from the reservoir results from the more permeable flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
Typically, a wellbore will intersect several hydrocarbon-bearing formations. Each formation may have a different fracture pressure. To ensure that each formation is treated, each formation is treated separately while isolating a previously treated formation from the next formation to be treated. To facilitate treating of multiple formations in one trip, a first formation may be treated and then isolated from the next formation to be treated using a removable isolation device, such as ball sealers. The ball sealers at least substantially seal the previously treated formation from the next formation to be treated.
FIG. 1A illustrates a prior art wellhead assembly 1 that may be utilized for a one-trip multiple formation treatment operation. The wellhead assembly 1 includes a lubricator system 2 suspended high in the air by crane arm 6 attached to crane base 8. First and second portions of a wellbore 50 have been drilled and lined with surface casing 55a partially or wholly within a cement sheath 52a and a production casing 55b partially or wholly within a cement sheath 52b. The depth of the wellbore 50 would extend some distance below the lowest interval to be stimulated to accommodate the length of the perforating device that would be attached to the end of the wireline 30. Wireline 30 is inserted into the wellbore 50 using the lubricator system 2. Also installed to the lubricator system 2 are wireline blow-out-preventors (BOPs) 10 that could be remotely actuated in the event of operational upsets. The crane base 8, crane arm 6, lubricator system 2, BOPs 10 (and their associated ancillary control and/or actuation components) are standard equipment components that will accommodate methods and procedures for safely installing a wireline perforating gun (see FIG. 1B) in the wellbore 50 under pressure, and subsequently removing the wireline perforating gun from a wellbore 50 under pressure.
The lubricator system 2 is of length greater than the length of the perforating gun to allow the perforating device to be safely deployed in a wellbore under pressure. Depending on the overall length requirements, other lubricator system suspension systems (fit-for-purpose completion/workover rigs) could also be used. Alternatively, to reduce the overall surface height requirements a downhole deployment valve could instead be used as part of the wellbore design and completion operations.
Several different wellhead spool pieces may be used for flow control and hydraulic isolation during rig-up operations, stimulation operations, and rig-down operations. The crown valve 16 provides a device for isolating the portion of the wellbore above the crown valve 16 from the portion of the wellbore below the crown valve 16. The upper master fracture valve 18 and lower master fracture valve 20 also provide valve systems for isolation of wellbore pressures above and below their respective locations. Depending on site-specific practices and stimulation job design, it is possible that not all of these isolation-type valves may actually be required or used.
The side outlet injection valves 22 provide a location for injection of treatment fluids into the wellbore. The piping from the surface pumps and tanks used for injection of the treatment fluids would be attached with appropriate fittings and/or couplings to the side outlet injection valves 22. The treatment fluids would then be pumped into the production casing 55b via this flow path. With installation of other appropriate flow control equipment, fluid may also be produced from the wellbore using the side outlet injection valves 22. The wireline isolation tool 14 provides a means to protect the wireline from direct impingement of proppant-laden fluids injected in to the side outlet injection valves 22.
FIG. 1B illustrates a prior art ball sealing operation 100 in progress. A tool string assembly 101 is deployed via the wireline 30. The tool string assembly 101 includes a rope-socket/shear-release/fishing-neck sub 110, casing collar-locator 112, a perforation gun 122a-d for each formation 150a-d to be treated, a setting tool (with adapter kit) 130, and a frac plug 135 (shown already set and detached from tool string 101). Each perforation gun 122a-d contains one or more perforation charges 124a-d and is independently fired using a select-fire firing head 120a-d. 
The frac plug 135 has been run-in and set at a first desired depth below a first planned perforation interval 140a using the setting tool 130. The tool string 101 was then positioned in the wellbore with perforation charges 120a at the location of the first formation 150a to be perforated. Positioning of the tool string 101 was readily performed and accomplished using the casing collar locator 112. Then the perforation charges 124a were fired to create the first perforation interval 140a, thereby penetrating the production casing 55b and cement sheath 52b to establish a flow path with the first formation 150a. 
After perforating the first formation 150a, the treatment fluid was pumped and positively forced to enter the first formation 150a via the first perforation interval 140a and resulted in the creation of a hydraulic proppant fracture 145a. Near the end of the treatment stage, a quantity of ball sealers 155, sufficient to seal the first perforation interval 140a, was injected into the wellbore 50. Following the injection of the ball sealers 155, pumping was continued until the ball sealers 155 reached and sealed the first perforation interval 140a. With the first perforation interval 140a sealed by ball sealers 155, the tool string 101, was then repositioned so that the perforation gun 122b would be opposite of the second formation 150b to be treated. The perforation gun 150b was then be fired to create the perforation interval 140b, thereby penetrating the casing 55b and cement sheath 52b to establish a flow path with the second formation 150b to be treated. The second formation 150b may be then treated and the operation continued until all of the planned perforation intervals have been created and the formations 150a-d treated.
The prior art setting tool 130 is a hindrance to the fracturing operation 100 due to the relatively small radial clearance between an outer surface of the setting tool 130 and an inner surface of the production casing 55b. The setting tool 130 may obstruct delivery of the ball sealers 155 to the intended perforation interval, dislodge ball sealers 155 already set in a particular perforation interval, and/or become stuck in the wellbore due to interference with the ball sealers 155.
Therefore, there exists a need in the art for an improved setting tool and/or adapter kit for setting a wellbore plug.